FIG. 1 illustrates a production tubing string 13 deployed in a cased natural gas wellbore 101 having an extended perforated interval 102. The production rate of a natural gas well is a function of the pressure differential between the underground reservoir and the well head. This differential is decreased by back pressure against the reservoir pressure. As natural gas and associated liquids are extracted during production, a gradual loss of reservoir pressure occurs in some natural gas wells, thus decreasing the pressure differential. Natural gas wells produce liquids such as water and hydrocarbon. Removal of these produced liquids depends on the velocity of the gas stream produced from the formation. As reservoir pressure and flow potential decrease, there is a corresponding drop in the flow velocity of the natural gas through the production tubing to the well head. Eventually, when the flow velocity becomes insufficient to overcome the “fall back” velocity of the liquids, a column of liquids accumulates in the well bore. This phenomenon referred to as liquid loading decreases the production of the well because the weight of the fluid column above the producing formation causes additional back pressure, which the reservoir must overcome. The critical velocity is the flow velocity or flow rate(mcf/d) required to overcome this pressure differential needed to lift produced fluids to surface.
FIG. 2 illustrates one of the methods that have been used in the art to overcome the problem of liquid loading. Production tubing 13 is extended to include a ported tubing section 17 and a “dead string” 14. Ported tubing section 17 can be a length of production tubing, for example one joint of production tubing or a smaller length of tubing i.e., a pup joint, having holes 18 drilled therein. The inner diameter (ID) of production tubing section 13 and the ID of dead string 14 are isolated from each other by plug 15. Alternatively, this design can include a “bull plug” on the bottom of dead string 14 to force the flow up to the ported section 17. Thus, fluids do not flow through the ID of dead string 14. Rather, the function of dead string 14 is to decrease the area of the annular space 106 between the dead string and the face of the wellbore (or casing). During operation, gas and formation fluids 11 in perforated interval 102 flow in the annular region 106 around dead string 14. Dead string 14 typically has a larger outer diameter (OD) than production tubing section 13, though the dead string 14 can also be the same size as the production tubing 13. For example, in a well with 4½″ casing having an ID of 4″, the production string might have an OD of 2⅜″ and the dead string might have an OD of 2⅞″. Dead string 14 reduces the flow area in the perforated interval, thereby decreasing the required flow rates (critical velocities) to lift produced liquid in the wellbore to surface and reduce the effects of liquid loading. Formation fluids and gas 11 cross over into the production tubing section 13 via holes 18 in ported tubing section 17.
Perforated regions of a gas well often produce sand, which can stick to the tubing (i.e., to dead string 14 inside the casing), fill the tubing, or fill the wellbore below the dead string 14. Several actions that well operators would typically perform to diagnose and correct these sand problems are not possible with the apparatus illustrated in FIG. 2. and other dead string installations or designs known in the art. For example, plug 15 isolating the dead string from the production string (or a permanent “bull plug” on the bottom of dead string 14, as mentioned above) prevents an operator from accessing the wellbore below the apparatus. Thus the operator lacks the ability to run a wireline to the bottom of the wellbore to check for sand fill levels below the dead string 14. Also, when a tubing string becomes stuck in sand or when the bottom of tubing string becomes filled with sand, i.e., “sanded in,” an operator typically tries to establish fluid flow to the bottom of the tubing string and back up through the annular region to disengage the string from the sand. This operation is not possible with the configuration illustrated in FIG. 2 because the holes in 17 can not be isolated and the bull plug would prevents the ability to get circulation fluids to the bottom of the production tubing.
Another deficiency in the configuration illustrated in FIG. 2 is that perforated tubing section 17 limits an operator's ability run fluid down the annular region between the tubing and the casing to the bottom of the wellbore because such fluids would tend to cross over into the ID of the tubing via holes 18. Thus, the configuration illustrated in FIG. 2 severely limits an operator's ability to access regions of the wellbore below plug 15, for example, to deliver chemical foamer to the end of the dead string.